EXC 10-K & 10-Q changes, risk factors and insider trading
Exelon Corp. · Nasdaq · Electric & Other Services Combined · CIK 1109357 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
Removed heading “The activities associated with the past Deferred Prosecution Agreement and the now resolved associated SEC investigation could have a material adverse effect on Exelon’s and ComEd’s reputation and relationship with legislators, regulators, and customers that could affect their ability to achieve actions and approvals (Exelon and ComEd).”
Largest changes
“The activities associated with the past Deferred Prosecution Agreement and the now resolved associated SEC investigation could have a material adverse effect on Exelon’s and ComEd’s reputation and relationship with legislators, regulators, and customers that could affect their ability to achieve actions and approvals (Exelon and ComEd).”see in full comparison
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain, are subject to operational failure and could be impacted bysee in full comparisonlackdisruptionsoforavailabilitycostofincreases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs which could result in potential liability (All Registrants).
“On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement with the USAO for the Northern District of Illinois to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and no charges were brought against Exelon. …”see in full comparison
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by the insufficiency of generation or energy storage resources to meet demand, transmissionsee in full comparisoncongestioncongestion, and failures of neighboring transmission systems (All Registrants).
“The DPA and the settlement with the SEC could have a material adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers, and other stakeholders. Those impacts could affect, or make more difficult, their efforts to achieve actions or approvals associated with operations. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for more information regarding the DPA and SEC settlement.”see in full comparison
“Energy storage systems provide additional resources for enhancing grid reliability and stability by providing rapid response capabilities, allowing the injection and absorption of power during electric supply and demand imbalances. As forecasted load increases, the lack of sufficient energy storage growth may also lead to greater price volatility and challenges in power services for customers.”see in full comparison
Full comparison: every changed paragraph (16)
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, along with adoption of new rate structures and constructs, or establishment of new rate cases, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which leadleads to uncertainty as to the ultimate result, and which could result in uncertainties in rate case outcomes, and/or introduce time delays in effectuating rate changes (All Registrants).
Risks include changes to energy systems due to new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state, or federal regulatory requirements intended to reduce GHG emissions and/or mandate implementation of energy conservation programs, including through limitation of the use of natural gas. Changes to current state legislation or the development of Federal legislation that requires the use of low-emission, renewable, and/or alternate fuel sources could significantly impact the Utility Registrants, especially if timely cost recovery is not allowed. In addition, where requirements and compliance mechanisms have previously been established, the withdrawal of such requirements can introduce costs and uncertainty.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart grid, DERs and energy efficiency programs, could increase capital expenditures and could significantly impact the Utility Registrants' consolidated financial statements if timely cost recovery is not allowed. These energy conservation programs, regulated energy consumption reduction targets, and new energy consumption technologies for PECO, could cause declines in customer energy consumption and lead to a decline in the Registrants' earnings, if timely recovery is not allowed.
The activities associated with the past Deferred Prosecution Agreement and the now resolved associated SEC investigation could have a material adverse effect on Exelon’s and ComEd’s reputation and relationship with legislators, regulators, and customers that could affect their ability to achieve actions and approvals (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement with the USAO for the Northern District of Illinois to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and no charges were brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provided that the USAO would defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period. That period expired, and the pending charge was dismissed, in July 2023. In October 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. On September 28, 2023, Exelon and ComEd reached a settlement with the SEC to fully resolve the matter.
The DPA and the settlement with the SEC could have a material adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers, and other stakeholders. Those impacts could affect, or make more difficult, their efforts to achieve actions or approvals associated with operations. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for more information regarding the DPA and SEC settlement.
Risks from cybersecurity and physical threats to energy infrastructures and personnel are increasing. Threat actors, including sophisticated nation-state actors and criminal groups, exploit potential vulnerabilities in the electric and natural gas utility industry, grid infrastructure, and other energy infrastructures. Attacks and disruptions, which could involve physical, cyber, and hybrid targeting of physical and cyber assets, are increasingly sophisticated and dynamic. Physical attacks targeting the Registrants' physical assets or personnel could cause injuries, damage, or operational disruptions. The increased implementation of, and reliance on, information technologies and networks to manage business operations, including the operation of technical systems, as well as the Registrants' use of numerous vendors and suppliers, create additional points of vulnerability that could be, and in certain instances have been, exploited by malicious threat actors. Several U.S. government agencies have warned that the energy sector and its supply chains are subject to increasing risks of physical attacks, ransomware attacks and cybersecurity threats, and that the risks may escalate during periods of heightened geopolitical tensions. In addition, the rapid evolution and increased adoption of artificial intelligence technologies may intensify the Registrants' cybersecurity risks.
The Registrants face a risk that their operations would be direct targets or indirect casualties of attacks or sabotaged by nation-states or their agents, or by foreign or domestic terrorist groups. Responses to such attacks or sabotage, and any resulting retaliatory actions or sustained conflict could affect the Registrants’ operations and finances in unpredictable and material ways. Furthermore, such events could compromise the physical or cybersecurity of the Registrants' facilities, which could adversely affect the Registrants' ability to manage their businesses effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, public health crises, epidemics, pandemics, credit crises, recession, sustained high inflation, or other significant events also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants periodically perform analyses to better understand long-term projections of climate change and how those changes in the physical environments where they operate could affect their facilities and operations. The Registrants primarily operate in the Midwest and Mid-Atlantic of the United States, areas that historically have been prone to various types of severe weather events, and the Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be at greater risk of damage as changes in the global climate affect temperature and weather patterns, including if such climate changes result in more intense, frequent and extreme weather events, elevated or decreased levels of precipitation, sea level rise, increased surface water temperatures, wildfires and/or other effects.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain, are subject to operational failure and could be impacted by lackdisruptions ofor availabilitycost ofincreases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs which could result in potential liability (All Registrants).
Lack of sufficient generation and energy storage to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties could interrupt transmission and distribution services, impair economic development, cause outages, and result in use limitations or affordability implications for customers. (All Registrants)
Exelon does not generate the electricity it delivers. The Utility Registrants purchase, transmit, and distribute electric power obtained from power generation facilities owned by third parties. This power is primarily procured through contracts as directed by the Utility Registrants’ respective state laws and regulatory commission actions from various approved bidders or from purchases on the PJM operated markets. Third-party power generation may be insufficient to meet our customers’ electricity demand in the short- and medium-term because of extreme weather, fuel security, market procurement, regulatory requirements, operational issues, maintenance outages, inflexibility of demand, or financial uncertainty impacting existing or prospective generation facilities. Faster energy demand growth, acceleration of generator retirements, or the limited entry of new generating resources in any of the Utility Registrants’ respective service territories may result in a longer-term power generation capacity shortfall. Exelon has forecast substantial increases in load, driven largely by the increasing use of data processing facilities dedicated to cloud services, artificial intelligence technologies.technologies, and other applications. If third-party power generation capacity is insufficient to meet any Utility Registrant’s customers’ electricity demand or customers’ electricity demand across PJM over any period, transmission and distribution services may be diminished or interrupted, and results of operations, financial condition, and cash flows could be adversely affected.
Energy storage systems provide additional resources for enhancing grid reliability and stability by providing rapid response capabilities, allowing the injection and absorption of power during electric supply and demand imbalances. As forecasted load increases, the lack of sufficient energy storage growth may also lead to greater price volatility and challenges in power services for customers.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be negatively impacted by the insufficiency of generation or energy storage resources to meet demand, transmission congestioncongestion, and failures of neighboring transmission systems (All Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As is the case for electric utilities generally, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures. Delays in siting, permitting, and interconnection could defer the introduction of new generation or energy storage resources that could address resource adequacy concerns.
An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 76 — Property, Plant, and Equipment, Note 11N/A — Asset Impairments, and Note 1210 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill impairments.
Management's Discussion & Analysis (MD&A)
New heading “Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL)”
New heading “Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).”
New heading “Residential Universal Bill Credit (Exelon and ACE).”
New heading “One Big Beautiful Bill Act (All Registrants).”
Removed heading “PJM Regional Transmission Expansion”
Largest changes
“As of December 31, 2024, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. …”see in full comparison
“As of December 31, 2025, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. …”see in full comparison
“Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. …”see in full comparison
“Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. …”see in full comparison
“While the 2024 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.”see in full comparison
“While the 2025 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.”see in full comparison
Full comparison: every changed paragraph (180)
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations by Registrant for the year ended December 31, 20242025 compared to the same period in 2023.2024. For additional information regarding the financial results for the years ended December 31, 20242025 and 2023,2024, see the discussions of Results of Operations by Registrant.
Year Ended December 31, 20242025 Compared to Year Ended December 31, 2023.2024. Net income attributable to common shareholders from continuing operations increased by $132$308 million and Diluted earnings per average common share from continuing operations increased to $2.73 in 2025 from $2.45 in 2024 from $2.34 in 2023 primarily due to:
•Favorable impacts of rate increases at BGEComEd, PECO, BGE, and PHI;
•Less unfavorableFavorable weather at PECO;
•Higher AFUDC at ComEd;
•Lower contracting costs at PHI;
•ALower income tax repairs deductionexpense at PECO;
•Favorable impacts of multi-year plans reconciliations at Pepco;
•Absence of realized losses from hedging activity at Exelon Corporate;
•Higher transmission peak load due to higher energy demand at ComEd; and
•Lower storm costs at PHI.BGE; and
•Impacts of the multi-year plan reconciliation at BGE.
•Lower impacts of multi-year plans reconciliations at BGE;
•Higher depreciation and amortization expense at PECO, BGE,PECO and PHI;
•Lower electric distribution earnings from lower allowed ROE and the absence of a return on the pension asset at ComEd;
•Higher creditcontracting loss expensecosts at PECO and BGEPHI;
•Lower transmission peak load due to lower energy demand at ComEd;
•Absence of the Maryland multi-year plan reconciliations at PHI;
•Charitable contributions at Exelon Corporate;
•Lower AFUDC at PHI; and
•Higher income tax expense at Exelon Corporate.
•Lower carrying cost recovery related to the CMC regulatory asset at ComEd; and
•Higher storm costs at BGE.
The following table provides a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 20242025 compared to 20232024:
(a)Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense and Other, net.
(ba)Primarily represents severance and reorganization costs related to cost management.
(b)Represents the disallowance of certain capitalized costs.
(c)In 2023, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment. In 2024, reflects the adjustment to state deferred income taxes due to change in DPL's Delaware net operating loss valuation allowance. In 2025, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
InDuring the third quarter 2024,2025, Exelon issued approximately 416 million shares of Common Stock at ana averagenet grossweighted-average price of $37.60$43.24 per share. The net proceeds from the 20242025 issuances were $148$691 million, which were used for general corporate purposes. See Note 1917 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.
On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The final settlement is subject to FERC approval. The existing loss estimate iswas reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.
For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that isare being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.
ManagementThe willUtility continueRegistrants, toexcept workfor collaborativelyPECO, with the Registrants’ regulatory commissions to filefiled PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving theirthe own PLRsPLR from the IRS.
On November 15, 2021, President Biden signed the $1.2 trillion IIJA was signed into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.
On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. In the fourth quarter of 2025, Exelon, ComEd, and BGE elected to decline the previously awarded Middle Mile Grant (MMG) and Exelon and PECO elected to decline the previously awarded Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE) grant. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, PECO, and BGE will continue to evaluate whether to move forward with these projects.
Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL)
On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $10 million and Regulatory liabilities of $3 million for multi-year plan reconciliations that are no longer eligible to be filed. DPL also derecognized Regulatory liabilities of $0.4 million during the second quarter of 2025 for multi-year reconciliations ineligible to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.
Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).
As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits were distributed to residential customers based on their consumption of electricity supply that was subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received approximately $49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer accounts receivable balances within the third quarter of 2025. Additional disbursements from the state of Maryland were received by BGE, Pepco, and DPL on February 3, 2026 for approximately $49 million, $21 million, and $8 million, respectively. These amounts will also be used to reduce residential customer receivables in the first quarter of 2026.
In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $30 per residential customer for the months of July and August 2025, which was deferred to Regulatory assets. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs. As of December 31, 2025, the Regulatory asset has a remaining balance of $10 million.
Residential Universal Bill Credit (Exelon and ACE).
In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the Residential Universal Bill Credit (RUBC), which will be funded by the NJBPU. The program provided a $50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued all bill credits to residential customers in September and October. As of December 31, 2025, there is no Regulatory liability remaining.
One Big Beautiful Bill Act (All Registrants).
On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.
In March 2023, Exelon, ComEd, and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of DERs and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In October 2023, ComEd’s project, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, was recommended by the Grid Deployment Office (GDO) for negotiation of a final award up to $50 million. This project will enable ComEd and its local partners to deploy the next generation of grid technologies that support the growth of solar and electric vehicles (EVs), while piloting new local workforce training initiatives to support job creation connected to the clean energy transition. The award negotiation process is complete and funding has been obligated.
In April 2023, ComEd, PECO, BGE, and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. In October 2023, PECO’s project, Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE), was recommended by the GDO for negotiation of a final award up to $100 million. This project will support critical electric infrastructure investments to help reduce the impact of extreme weather and historic flooding on the Registrants' electric distribution system. The award negotiation process is complete and funding has been obligated.
The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. In October 2023 the DOE announced it selected two of the projects for further negotiation: (1) the Mid-Atlantic Clean Hydrogen Hub (MACH2), which is being supported by PECO and PHI, and (2) the Midwest Alliance for Clean Hydrogen (MachH2), which is being supported by ComEd.
In November 2023, the GDO announced up to $3.9 billion available through the second-round funding opportunity of the Grid Resilience and Innovation Partnerships (GRIP) Program for fiscal years 2024 and 2025. This funding opportunity focuses on projects that will improve electric transmission by increasing funding and advancing interconnection processes for faster build out of energy projects, create comprehensive solutions that link grid communications systems and operations to increase resilience and reduce power outages and threats, and deploy advanced technologies such as distributed energy resources and battery systems to provide essential grid services to ensure American communities across the country have access to affordable, reliable, clean electricity. In March 2024, Exelon, BGE, PHI, Pepco, DPL, and ACE submitted five applications for Topic Area 2 (Smart Grid Grants). These applications focus on improving resilience of the electric grid and deployment of technologies to enhance grid flexibility and deliver benefits to customers across the Exelon footprint.
In October 2024, Exelon’s project, Renewable-Aware Distribution Operations: Pioneering a cleaner future for all our communities, and BGE’s project, Baltimore Interconnection Readiness & Deployment of Storage (BIRDS), were recommended by the GDO for negotiation of a final award up to $100 million and $50 million, respectively. The Exelon project will deploy advanced Distribution Energy Resource Management System (DERMS) capabilities and pilot technology to increase the flexibility, efficiency, reliability, and resilience of its distribution network. BGE’s project will facilitate a programmatic approach to a flexible and decentralized energy distribution grid while setting an automated and digitized framework for unlocking future clean energy investments. Both the Exelon and BGE projects have been issued conditional awards, subject to final negotiations.
The Trump Administration has issued numerous Executive Orders (EOs), including the Unleashing American Energy Order on January 20, 2025, which requires an immediate pause in the disbursement of funds appropriated through the IRA and IIJA during a 90-day review period. Exelon is currently evaluating this EO and others to determine what, if any, impact they might have on awards selected or received from the Department of Energy.
PJM Regional Transmission Expansion
At the February 4, 2025 Transmission Expansion Advisory Committee meeting, PJM disclosed PECO’s, BGE’s and Pepco’s revised total estimated costs for the planned retirement of the Brandon Shores Generating Station of approximately $154 million, $1.1 billion, and $241 million, respectively.
As of December 31, 2024, Exelon’s $6.6 billion carrying amount of goodwill consists of $2.6 billion at ComEd and $4 billion at PHI. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion, respectively. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
While the 2024 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could be material.
See Note 1 — Significant Accounting Policies and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized energy contract liabilities represent the remaining unamortized balances of non-derivative electricity contracts that Exelon acquired as part of the PHI merger. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. Offsetting regulatory assets were also recorded for those energy contract costs that are probable of recovery through customer rates. The unamortized energy contract liabilities and the corresponding regulatory assets, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract liabilities are recorded through Purchased power and fuel expense. See Note 3 — Regulatory Matters and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.
Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.
See Note 1 — Significant Accounting Policies and Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and OPEB plans.
(a)Exelon's charge against OCI (before taxes) consists of up to $2.2$2.4 billion, $363$346 million, $384$298 million, $253 million, $95$214 million, and $7$75 millionmillion, related to ComEd's, BGE's, PHI's, Pepco's, DPL's, and ACE'sDPL's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of $106 million (before taxes) of $86 million and $6 million related to PECO’sPECO's portionand ACE's portions of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.
What changed in the latest 10-Q
Risk Factors
Risks Related to All Registrants
At June 30, 2026, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2025 Form 10-K in ITEM 1A. RISK FACTORS.
Full comparison: every changed paragraph (1)
At MarchJune 31,30, 2026, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2025 Form 10-K in ITEM 1A. RISK FACTORS.
Management's Discussion & Analysis (MD&A)
New heading “At-the-Market Program”
New heading “Transmission Formula Rates”
New heading “Exelon’s Cost Saving Strategy (All Registrants)”
New heading “New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE)”
New heading “Delaware Senate Bill 326 (Exelon, PHI, and DPL)”
Largest changes
Exelon Corporate, ComEd, and BGE meet their short-term liquiditysee in full comparisonrequirementsneeds primarily throughthe issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance ofcommercial paperandissuances. PECO also utilizes commercial paper, supplemented by borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACEmeetsimilarlytheirrelyshort-term liquidity requirements primarily through the issuance ofon commercialpaperpaper,andalong with borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidityrequirements primarilyneeds throughtheborrowingsissuance of short-term notes andfrom the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Full comparison: every changed paragraph (126)
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the three and six months ended MarchJune 31,30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and six months ended MarchJune 31,30, 2026 and 2025, see the discussions of Results of Operations by Registrant.
Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025. Net income attributable to common shareholders increased by $11$5 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.90$0.39 primarily due to:
•Absence of Customer Relief Fund contribution at Exelon Corporate;
Note that rate increases are associated with updated recovery rates for costs and investments to serve customers. The increases were partially offset by:
•Higher depreciation expense at PECO and PHI;
•Higher interest expense at PECO and Exelon Corporate; and
•Higher credit loss expense at BGE.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income attributable to common shareholders increased by $15 million and diluted earnings per average common share decreased to $1.28 in 2026 from $1.29 in 2025 primarily due to:
•Favorable impacts of approved rate increases at ComEd, BGE and PHI;
•Absence of Customer Relief Fund contribution at Exelon Corporate;
•Absence of Customer Surcharge Credits at PECO;
•Higher AFUDC at ComEd; and
•Favorable weather at PECO;
•Higher interest expense at PECO, PHI, and Exelon Corporate;
•Higher interest expense at PECO and Exelon Corporate;
The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and six months ended MarchJune 31,30, 2026 compared to the same period in 2025:
(a)Primarily represents severance and reorganization costs related to cost management.management program.
(b)Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.
(bc)Represents the disallowance of certain capitalized costs.
At-the-Market Program
In the second quarter of 2026, Exelon issued approximately 8.7 million shares of Common stock at a weighted-average net price of $44.03 per share. The net proceeds from the issuance were $382 million, which were used for general corporate purposes. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Formula Rates
For 2026, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Exelon’s Cost Saving Strategy (All Registrants)
In May 2026, Exelon announced plans to identify approximately $350 million of operating and maintenance costs savings at Exelon and the Utility Registrants in 2027. This announcement is a result of Exelon’s continuous focus on the needs of our customers through enhanced efficiency and productivity.
Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL)
On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July 2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50-basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.
On April 13, 2026, the Maryland Utility RELIEF Act (Utility RELIEF Act) was passed through the Maryland General Assembly and awaits the Governor’s signature to become law. If and when the Utility RELIEF Act becomes law, it will modify the regulatory framework and rules governing recovery of certain costs in utility ratemaking in Maryland. Exelon, BGE, Pepco, and DPL are in the process of assessing the potential impacts of the pending legislation.
PJM Cost Allocation Methodology (All Registrants).
On March 6, 2026, FERC issued an order requiring the removal of the de minimis threshold exemption in the calculation of the cost responsibility of certain transmission reliability upgrade costs allocated to the rate zones of PJM transmissionTransmission owners,Owners, including the Utility Registrants. FERC further ordered PJM to recalculate historical cost allocations for the period beginning June 18, 2015, and to pass through additional charges or payments to PJM customers, including Utility Registrants, as applicable, with interest within 90 days. On April 29, 2026, the time for those calculations was extended until further order from FERC. The Utility Registrants expect to recover any incremental charges incurred or reimburse any payments received through prospective electric customer rates. On April 6, 2026, a number of parties filed petitionsrequests for rehearing or clarification.clarification, which were denied by operation of law on May 7, 2026. On May 12, 2026, PJM Transmission Owners, including Exelon, on behalf of the Utility Registrants, filed a petition for review at the United States Court of Appeals for the D.C. Circuit.
New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE)
On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50-basis-point incentive adder in the transmission formula rates.
Delaware Senate Bill 326 (Exelon, PHI, and DPL)
On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5% of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50% of the proposed rate increase, subject to refund. If no decision has been issued after 12 months, DPL may implement 75% of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of MarchJune 31,30, 2026, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2025 Form 10-K for further information.
Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025. Net Income increased by $8$21 million as compared to the same period in 20252025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.AFUDC.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income increased by $29 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.
Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues decreasedincreased for the three and six months ended MarchJune 31,30, 2026 as compared to the same periodperiods in 2025, primarily due to lowerhigher rate base and higher fully recoverable costs.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs,costs and capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year.recovered. Transmission revenues increased for the three and six months ended MarchJune 31,30, 2026 compared to the same periodperiods in 2025, primarily due to higher fullyrate recoverable costsbase and higher ratefully base.recoverable costs.
Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three and six months ended MarchJune 31,30, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increaseddecreased for the three and six months ended MarchJune 31,30, 2026 as compared to the same periods in 2025, which primarily reflects increaseddecreased mutual assistance revenues associated with storm restoration efforts.
The decreaseincrease of $238$29 million for the three months ended MarchJune 31,30, 2026 and the decrease of $208 million for the six months ended June 30, 2026, compared to the same periodperiods in 20252025, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.
(a)Primarily reflects the probable disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.
Other, net increased $10 million and $20 million for the three and six months ended MarchJune 31,30, 20262026, respectively, compared to the same periodperiods in 2025, primarily due to higher AFUDC equity.
Effective income tax rates were 24.6%25.0% and 17.7%18.6% for the three months ended MarchJune 31,30, 2026 and 2025, respectively, and 24.8% and 18.1% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025. Net incomeIncome increaseddecreased by $12$17 million due to an increase in revenuedepreciation, asinterest expense, tax repairs, a resultportion of which is timing, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather relative to the same period last year, and tax repairs, some of which is timing, partially offset by an increase in depreciation and interest expense.weather.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income decreased by $5 million due to an increase in depreciation, interest expense, and severance costs related to the cost management program, partially offset by higher revenues resulting from the absence of surcharge credits to customers, and favorable weather.
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended MarchJune 31,30, 2026, compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and six months ended MarchJune 31,30, 2026, compared to the same period in 2025, and normal weather consisted of the following:
Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended MarchJune 31,30, 2026 compared to the same period in 2025, remaineddecreased relativelydue consistent.to customer load. Natural gas volume for the three and six months ended MarchJune 31,30, 2026, compared to the same period in 2025, remained relatively consistent.
Pricing for the three and six months ended MarchJune 31,30, 2026, compared to the same period in 2025, remained relatively consistent.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and six months ended MarchJune 31,30, 2026, compared to the same period in 2025, increased primarily due to increases in the underlying costs and capital investments.
Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended MarchJune 31,30, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.
The increase of $110$50 million and $160 million for the three and six months ended MarchJune 31,30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
(a)Reflects severance related to cost management program
Taxes other than income taxes increased by $8 million and $16 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to higher Pennsylvania gross receipts tax.
Interest expense, net increased by $12 million and $20 million for the three and six months ended June 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in interest rates and higher outstanding debt.
Effective income tax rates were 5.1%6.3% and 5.0%2.9% for the three months ended MarchJune 31,30, 2026 and 2025, respectively, and 5.5% and 4.1% for the six months ended June 30, 2026 and 2025, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025. Net income increasedremained $38 millionconsistent primarily due to approved distribution ratesrates, the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025, and a decrease in various operating expenses, partially offset by an increase in credit loss expense.expense and severance costs related to the cost management program.
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. Net income increased $38 million primarily due to approved distribution rates, the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025, and a decrease in various operating expenses, partially offset by an increase in credit loss expense and severance costs related to the cost management program.
EXC insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
No Form 4 stock transactions in this period.
Well-known investors holding EXC (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| AQR Capital Management (Cliff Asness) | 2026-06-30 | 3,589,650 | $167.3M | 0.06% | Added 18% |
| Renaissance Technologies | 2026-06-30 | 1,513,124 | $70.5M | 0.1% | New position |
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 1,196,816 | $55.8M | 0.03% | Reduced 63% |
| Bridgewater Associates | 2026-06-30 | 366,296 | $17.1M | 0.07% | Added 2072% |
| Millennium Management (Israel Englander) | 2026-06-30 | 239,624 | $11.2M | 0.01% | Added 396% |
| Gotham Asset Management (Joel Greenblatt) | 2026-06-30 | 146,443 | $6.8M | 0.02% | Reduced 61% |
| Soros Fund Management | 2026-06-30 | 104,734 | $5.1M | — | Sold out |
| Baillie Gifford | 2026-06-30 | 86,157 | $4.0M | 0.0% | Reduced 60% |
| D. E. Shaw & Co. | 2026-06-30 | 51,927 | $2.4M | 0.0% | Reduced 8% |
| Two Sigma Investments | 2026-06-30 | 17,614 | $821.2K | 0.0% | Added 54% |